Prior art systems for controlling electricity in power distribution systems employ fuses, switches, sectionalizers, or automatic circuit reclosers to remove faulted portions of the distribution system so that non-faulted portions of the system can continue to provide electrical power to users who are not on the faulted portions of the system. The term "switchgear", as used herein, is to be interpreted to encompass fuses, switches, sectionalizers, breakers, and automatic circuit reclosers.
There are various problems associated with mechanical switchgear which will be discussed below.
In the field of electrical distribution systems, certain terms, mentioned above, are used that are commonly understood as set forth below.
A fuse is a protective device that basically includes a piece of wire that overheats and separates into two pieces when current through it exceeds a predetermined value. The time required for separation is inversely proportional to the magnitude of current passing through the fuse. That is, the larger the value of current, the faster the wire will separate.
A switch includes a moveable piece of conductive metal that is movable between a closed position for providing a current path through the switch, and an open position for preventing current from flowing through the switch. Switches are used to control loads which, in a distribution circuit, almost always comprises a transformer.
A sectionalizer is an automatic switch that has control circuitry, and separable contacts that are normally closed, but that open when the control circuitry determines that switchgear on the source side of the sectionalizer (i.e., up-line of the sectionalizer) has opened and closed a predetermined number of times. The sectionalizer always opens its contacts when the source side (up-line) device has its contacts open and, thus, no electricity is flowing. This allows the use of low cost, non-interrupting contacts in sectionalizers.
A recloser is an automatic device that has separable contacts and control means for measuring current flow through the recloser when the contacts are closed. If current is excessive, the control means causes the contacts to open. After a period of time which is determined based on avoiding overheating, the control means closes the contacts, e.g. by energizing a motor or a large solenoid. This open-close sequence can occur for up to a predetermined number of times in a given period before the control means prevents the contacts from reclosing. This condition where reclosing is prevented is referred to as "lockout".
Reclosers, as presently manufactured, have the ability to interrupt large values of fault currents, such as would be produced by two or more electrical lines shorting together or falling to ground. To provide this ability, the reclosers include specially designed electrical contacts made of special material so as to provide long life.
The different types of electrical contacts used in switchgear are usually referred to based on the type of insulating material used to prevent electrical flow when the contacts are open. The most common insulating materials include oil, vacuum, or SF.sub.6.
Where oil is used, an ionized gas is formed during arcing that occurs when the contacts are separated. The gas is exploded by the arcing of the hot electrical current and the explosion blows out the arc, in specially designed chambers, and deionizes the gas.
Where a vacuum is used, the contacts are enclosed in a vacuum by glass or porcelain. One of the contacts is moveable, and when moved to an open position, the vacuum atmosphere has no molecules to be ionized. Therefore, the electrical current is terminated at the first zero crossing point of the current sinusoid that occurs after the contacts have separated.
Where SF.sub.6 is used, SF.sub.6, which is an inert gas, is blown between contacts as they separate and while arcing occurs, until the first zero crossing point of current. Alternatively, the arc is rotated and the SF.sub.6 cools off the arc as it rotates, preventing arcing from reoccurring after the first zero crossing point of the current sinusoid.
The contacts in switchgear wear by a varying degree depending on the type of insulating material used, and depending on where in a current half-cycle the contacts separate. If the contacts separate late in the half-cycle, there is a relatively small amount of Volt-Ampere product that is to be dissipated as power and that causes erosion of the contact material. If the contacts separate early in the half-cycle, the Volt-Ampere product can be very large, and significant erosion of the contact material can take place. This is especially a problem in oil interrupters where contact erosion is a major problem anyway.
The contacts in switchgear also have problems associated with "restrike", wherein instead of an opening contact holding the current off after a zero crossing point of the current sinusoid, the contacts separate too slowly and high voltage applied to the contacts in a new half cycle cause the contact gap to be ionized and break down and carry current for the remainder of that half cycle.
A problem associated with vacuum contacts is that, at low voltages, the current stops or "chops" before getting to a zero crossing, causing stress to the electrical distribution system which has to dissipate the energy stored in the system reactances. These energies would otherwise be dissipated at the zero crossing point of current for a proper contact opening.
Another problem with mechanical switchgear is that a long period of time is required to open mechanical contacts. This opening time is on the order of one and one half cycles, from the time an opening signal is sent until the contacts actually separate, for vacuum and SF.sub.6 devices to two and a half cycles for oil devices. This time causes coordination problems when fuses used with the switchgear melt within one cycle.
A problem affecting an electrical distribution system that is protected by oil, vacuum, or SF.sub.6 protective devices is that when the contacts are closed to re-energize the distribution circuit, the time when the contacts are closed is random, with regard to the voltage sinusoid, and causes a phenomenon known as "magnetizing inrush current". Magnetizing inrush current occurs because when a portion of the distribution line has voltage removed, the transformers on that portion of the line are left with remnant magnetism on their cores. Magnetizing inrush current results in severe stress and perhaps damage to the equipment in the electrical distribution system. The degree to which the inrush current is a problem is directly related to the timing for disconnecting a load from and reconnecting the load to a power distribution system.
In view of the foregoing, there are many problems with using mechanical switchgear as overload protection means in a power distribution system. Therefore, it is desirable to use means other than mechanical switchgear as overload protection or for ordinary switching applications in a power distribution system. Solid state switches such as thyristors, bipolar transistors, and mosfets can be used instead of mechanical switchgear for overload protection and for directing the flow of power. See, for example, the following magazine articles: The Application of Photoconductive Switches in HVDC Circuit Interruption, by O. A. Ciniglio and D. P. Carroll, IEEE Power Engineering Review, January 1990; Field Evaluation of Industry's First Self-Protected, Light-Triggered Thyristor, by F. Cibulka, L. Crane, and J. Marks, IEEE Power Engineering Review, January 1990; Utility Power Quality Controls--A New Market for Power Electronics, by J. Douglas, PCIM, October 1989; and A Better Way to Protect Solid State Starters, by Tom Caputo, Machine Design, Sep. 12, 1991, all of which are incorporated herein by reference.
When completing a connection of a load to a power source in a power distribution system, it is desirable to connect at a zero crossing point of the sinusoid of the power source so as to avoid arcing or a condition which would cause the overload protection means to reopen, and to avoid introducing undesirable system transient conditions.
U.S. Pat. No. 3,703,680, issued to Frank et al. on Nov. 21, 1972, discloses a capacitor bank for use in a network where oscillations occur in reactive power. Anti-parallel thyristor branches are employed such that the thyristors are connected in one direction or the other in synchronism with the maximum network voltage. Connection and disconnection of the bank take place at zero crossing points of the network current. (see col. 3, lines 28-33).
U.S. Pat. No. 4,162,442, issued to Frank on Jul. 24, 1979, discloses a capacitor bank for voltage control connectable to an AC network through a bi-directional switch. After disconnection from the network, the capacitor bank is periodically made conducting to keep it charged with a voltage of constant polarity.
The circuits disclosed in each of these Frank patents are designed based on the assumption that system voltage will always be present. Neither of these patents address a situation where system voltage is interrupted. Further, neither of these patents address a situation where voltage is severely depressed.
One problem associated with using solid state switchgear, e.g. including anti-parallel thyristors or SCRs, is the problem of leakage currents flowing through the solid state switchgear device even when it is turned off. The problem of leakage currents is aggravated by a temperature rise that occurs when the thyristor has conducted a high value of current. For this reason, solid state switchgear has not been heretofore used as fault protection in a power distribution system.